To meet the significant growth in oil and gas demand today, exploration is moving to uncharted, ultra-deep water locations and production is being considered in locations previously considered to be off-limits. Further, much of the existing infrastructure typically operates well beyond its designed capabilities. This overreach creates significant technical challenges in all areas of production; however, no challenge is more difficult than preserving infrastructure integrity.
Corrosion inhibitors are frequently introduced into oil and gas fluids to aid in maintaining infrastructure integrity. Corrosion inhibitors are added to a wide array of systems and system components, such as cooling systems, refinery units, pipelines, steam generators, and oil or gas producing and production water handling equipment. These corrosion inhibitors are geared towards combating a large variety of corrosion types. For example, a common type of corrosion encountered in the transport of fluid having one or more corrosive agents is flow-induced corrosion, where the degree of corrosion depends on a multitude of factors. These factors include the corrosiveness of the fluid, pipeline metallurgy, shear rate, temperature, and pressure.
Injection of a high performance inhibitor at the appropriate location and optimum dosage can be extremely effective at reducing corrosion rates, such as on pipe walls. Observing a greater than 95% decrease in corrosion is not uncommon. Performance is typically determined through several techniques, such as electrical resistance probes, coupon measurements, and inspection readings. In some cases, however, corrosion inhibitor performance may deteriorate over time, particularly in systems that have a tendency to accumulate significant quantities of solids.
Depending on the particular system, these solids can build up to form a layer up to several centimeters thick. Deposits of such hydrocarbonaceous materials and finely divided inorganic solids form on the inner surfaces of the lines. These deposits may include, for example, sand, clays, sulfur, napthenic acid salts, corrosion byproducts, and biomass bound together with oil. The particles become coated with corrosion inhibitor or other hydrocarbonaceous materials and subsequently become coated with additional quantities of heavy hydrocarbonaceous material in the flowlines, settling tank, and the like. Collectively, this layer is often referred to as “schmoo” in the petroleum industry.
Schmoo is a solid or paste-like substance that adheres to almost any surface with which it comes in contact and is particularly difficult to remove. Whenever possible, pipelines known to have such deposited materials or that form pools of water at low spots are routinely pigged to remove the material. In many cases, however, it may not be feasible to pig lines due to the construction configuration, variable pipeline diameter, or the lack of pig launchers and receivers. The material often accumulates on, for example, the bottom or around the circumference of the pipe. Additionally, even after maintenance pigging, schmoo still often resides inside pits in metal surfaces. As discussed above, these situations create a significant risk for increased corrosion. Schmoo can also accumulate to a thickness such that it flakes off the inner surfaces of the pipe and deposits in the lower portion of a well, the lower portion of a line or the like, and plugs the line or the formation in fluid communication with the pipe.
The physical barrier formed by such a layer also retards the diffusion of corrosion inhibitors to the pipe wall. These solids also often have a strong affinity for corrosion inhibitors and may significantly reduce inhibitor availability in situ. Furthermore, the composition of matter within the solids forms an ideal environment to foster bacterial growth, the metabolic byproducts of which are frequently highly corrosive. This microbiologically influenced corrosion process has been recognized as a significant problem in the industry for many years. Additional challenges are encountered in water injection systems when material carried in the water causes plugging of the sand-face downhole. Such plugging often leads to reduction in water injection efficiency and a consequent reduction of the oil produced.
Moreover, stringent governmental regulations have imposed environmental constraints on the oil and gas producing industry. These regulations have led to the need for new “greener” chemistries, which have reduced environmental impact. The environmental impact of any chemical is typically defined by three criteria: biodegradation, bioaccumulation, and toxicity. All three criteria have benchmarks that must be met for a chemical to be permitted for use, with different emphasis on each depending on which regulatory body controls the waters. This environmental drive has been spearheaded by North Sea Regulators (e.g., CEFAS) and their success has sparked similar programs, currently being implemented in other oil producing regions. Operators now demand identical levels of performance with existing treatments along with the fulfillment of the new environmental criteria for any chemicals that may be contained, for example, in rig overboard discharge.
In view of these difficulties there exists an ongoing need for improved and environmentally friendly methods of removing deposits from pipelines to optimize oil production, particularly where water injection systems are used. An ideal solution would include a chemical-based process to remove the deposits, prevent further deposits from forming in the system, and optimize water volume (in many cases including maximizing water injectivity). Simultaneously protecting the system from corrosion caused by the presence of naturally occurring acidic species and bacterial byproducts would also be highly desirable.